EA006075B1 - Eletromagnetic method for determining dip angles independent of mud type and borehole environment - Google Patents

Abstract

A method employs an apparatus for generating a directional signal associated with the electromagnetic energy response of a subsurface formation. The method is useful to derive both the strike angle of formation boundary and the relative dip. The true dip and azimuth can be computed from the relative dip information coupled with borehole orientation. Other applications of the method are also described.

Description

1. The field to which the invention relates

The present invention generally relates to the field of well logging. More specifically, the present invention relates to improved methods in which devices equipped with antenna systems having a transverse or inclined representation of a magnetic dipole moment are used for electromagnetic measurements of subsurface formations and to determine the structure of reservoir bedding and formation dip, as well as the location of wells, relative to geological the boundaries of the tank.

2. The level of technology

Information characterizing falls in the studied subsurface formations is important for understanding the conditions of sedimentary rock deposition and for developing and implementing a well drilling profile for oil and gas exploration. Formation dip and strike can be obtained from seismic maps and well images. Seismic maps provide large-scale structure information, and well images provide information related to the local environment of the formation through which the well passes. Both types of information are useful information for hydrocarbon exploration. However, dip data from well images are usually more accurate than data from seismic maps.

In the field of hydrocarbon exploration and production, various well logging methods for assessing subsurface formations through which a well passes are well known in the art. Such methods typically use devices and tools equipped with sources configured to emit energy into the formation. In the present description, the tool and device will be used interchangeably to mean, for example, an electromagnetic tool (device), tool (or device) on a wireline cable or tool (or device) for logging while drilling. The emitted energy interacts with the surrounding formation to form signals, the detection and measurement of which is carried out using one or more sensors. By processing the data of the detected signals, the characteristics of the images or formation profile are obtained.

Industrial tools offered today for acquiring electrical images of the well include the CeoU1kup tool ΒοδίδΙίνίΙν (QMS) and the Λζίιηιιΐΐιαсп tool ESPIu №i1hop (ΑΌΝ) (both tools are used in the drilling process) and the RogtaNop M1 tool (δίδΐίνΐίκ 1) cable), all of them are the property and are offered by the World Bank, the assignee of the present invention. Drops are obtained from images of boreholes by recognizing reservoir boundaries in an image or by establishing relationships between images measured by various sensors. The accuracy of estimating the fall from the images is influenced by many factors, including the quality of the images, the vertical resolution of the tools, the professionalism of the geologist, and - in the waste wells - the accuracy of the geophysical study of the well.

Among the above imaging tools, the PM1 tool provides the highest quality of well images by using measuring electrodes that are small in size (for example, 0.2 inches). The accuracy of visible incidence in images constructed with the PM1 tool is typically around 0.5 ° for typical steep incidence angles (or incidence heights). For less visible drop, accuracy decreases to a few degrees. In addition, the PM1 tool and other electrode tools work only in conductive drilling fluid.

The QMS tool provides real-time studies of incidence angles, but only for visible incidence angles exceeding 53 °. Analysis on the surface of a real-time image can eliminate such limitations, but since the image is obtained using one-inch electrode pads, the image quality does not accurately determine the drop in the case of a small relative to the drop. High transmission speed can also affect image quality and, thus, the accuracy of incidence obtained from the image. Like the PM1 tool, the QMS tool only works in a conductive drilling fluid.

For hydrocarbon-based drilling fluids and synthetic drilling fluids, tool 011 Vake M1stoTadeg (OBM1) can also be used, also from BSiTetdeg, to provide imaging. Image quality is lower than that of the PM1 tool, and the fall detection error will be greater than that of the PM1 tool. Currently, there are no tools for obtaining an electrical image to determine the fall in both conductive and non-conductive drilling fluids.

Electromagnetic (EM) induction logging and electromagnetic wave logging are methods well known in the art. Logging tools for measuring the electrical conductivity (or its reciprocal, resistivity) of the geological formations surrounding the borehole are placed inside the borehole on a wireline or drill string during drilling. In the present description, any reference to conductivity implies its inverse, resistivity, or vice versa. Conventional electromagnetic measurement instrument

- 1 006075 resistivity contains a transmitting antenna and one or more (usually two) receiving antennas located at some distance from the transmitter antenna along the axis of the instrument (see Fig. 1).

Induction instruments measure the resistivity (or conductivity) of a formation by measuring the voltage induced in a receiving antenna (s) as a result of magnetic flux caused by alternating currents flowing through a radiating (or transmitting) antenna. So-called electromagnetic wave instruments work in the same way, but usually at higher frequencies than induction instruments with comparable distances between antennas (approximately 10 ⁶ Hz for electromagnetic wave instruments compared to 10 ⁴ Hz for induction instruments). A conventional electromagnetic wave instrument can operate in the frequency range 1 kHz - 2 MHz.

Traditional transmitters and receivers are antennas formed by coils containing one or more turns of an insulated conductive wire wound around a base. Such antennas typically work as sources and / or receivers. Those skilled in the art will appreciate that one antenna can be used as a transmitter at one point in time, and as a receiver at another. It is also obvious that the transmitter-receiver configurations described herein are interchangeable due to the principle of reversibility, i.e. The transmitter can be used as a receiver and vice versa.

Antennas operate according to the following principle, an alternating current coil (for example, a transmitting coil) generates a magnetic field. The electromagnetic energy of the transmitting antenna of the logging tool located in the borehole is transmitted to the surrounding areas of the formation, and such transmission induces eddy current flowing in the formation surrounding the transmitter (see Fig. 2a). The eddy current induced in the formation, which is a function of the resistivity of the formation, forms a magnetic field, which in turn induces an electrical voltage in the receiving antennas. When using a pair of spatially separated receivers, the voltage induced in the two receiving antennas will have different phases and amplitudes due to the geometric distribution and absorption of the surrounding formations. The phase difference (phase shift, F) and the amplitude ratio (attenuation coefficient, A) of the two receivers can be used to obtain the formation resistivity. The detected phase shift (Φ) and attenuation (A) depend not only on the distance between the two receivers and the distances between the transmitter and receivers, but also on the frequency of the EM waves generated by the transmitter.

In the induction logging tools and electromagnetic wave logging tools known from the prior art, receiving and transmitting antennas are mounted with their axes parallel to the longitudinal axis of the tool. Thus, these tools are made with antennas having a longitudinal magnetic dipole moment (PMD). In FIG. 2A shows a simplified representation of the electromagnetic (EM) energy emanating from such a logging tool located in a part or segment of a well passing through a subsurface formation in a direction perpendicular to the formation formation under study. However, this is not an accurate depiction of all of the many segments that make up the well — in particular if the well is directional, as described below. Thus, well segments often pass through formation layers at an angle other than 90 °, as shown in FIG. 2B. In this case, it is said that the formation plane has a relative fall. The relative dip angle, θ, is defined as the angle between the borehole axis (tool axis) of VA and the normal N to the plane P of the formation layer under study.

It is well known in the art that the response of a logging tool can be influenced by the formation structure of the formations surrounding the well segment in which the tool is located. For electromagnetic logging tools, this is known as the effect of adjacent formations. Accordingly, the responses of known induction instruments and electromagnetic wave instruments having PMD antennas are affected by formation layers and their falls. However, such tools are traditionally non-directional, and therefore unable to provide azimuthal information about the structure of the layers. Thus, commercially available induction tools for measuring resistivity on a wireline cable and electromagnetic wave tools for logging while drilling (b ^ U) are not currently able to accurately determine the dip.

A new method in the field of well logging is the use of tools that include antennas having inclined or transverse coils, i.e., in which the axis of the coils are not parallel to the longitudinal axis of the tool or well. Such instruments are thus implemented with antennas having a transverse or inclined magnetic dipole moment (NMD).

Those skilled in the art will appreciate that there are many methods for tilting or biasing an antenna. Logging tools equipped with NMD antennas are described, for example, in US Pat. Nos. 6,163,155; 6,147,496; 5,115,198; 4,319,191; 5508616; 5,757,191; 5,781,436; 6,044,325;

and 6147496. The response from such a tool depends on the azimuthal orientation of the tool in the inclined formation. Consequently, useful information about the geological structure, in particular, dip and erasure, can be obtained by suitable analysis of azimuthal or directional measurements.

U.S. Patent Application Publication No. 2003/0055565, Odd. the patent holder of which at the moment is Zsitetdeg, analytical expressions for calculating the parameters of the anisotropic formation from triaxial induction measurements are derived. US patent No. 6163155, B1yat, the patent holder of which is Egeszeg. discloses a method and apparatus for simultaneously determining horizontal resistivity, vertical resistivity and relative dip angle for anisotropic geological formations using software rotation of orthogonal coils to separate horizontal and vertical resistivity. US Patent No. 6,556,016 to Cao et al., The patent holder of which is HIGH, discloses an induction method for determining the approximate angle of incidence of an anisotropic geological formation using triaxial measurements. These applications are limited to formations with anisotropy.

Definitions Used In The Present Description

Certain terms are defined in the present description upon their first use, while other specific terms used in the present description are defined below.

Visible dip means the angle that the (inclined) formation makes with the horizontal plane, when measured in any direction other than the perpendicular to the strike.

Formation or stratification means the stratification or stratification of sediments or deposits, which usually occur in subsurface formations (usually rock formations).

Binning means the sorting of measured signals — in particular, formation responses to transmitted electromagnetic energy — into groups based on parameter values, and can be carried out for one parameter determined from the signal or for several parameters. An example of a binning criterion may be the frequency or period of a signal component. Another example is the relationship of the measured signal with the azimuthal angle of orientation of the instrument.

Dip or dip angle means the angle that the (inclined) formation makes with the horizontal plane when measured perpendicular to the strike.

Inversion or inverse means the derivation of a model (otherwise called an inverse model) from the measured data (for example, log data), which gives the answers that are most consistent with the measured data according to a specific criterion. For example, a measured signal can be used to recreate a subsurface formation model that provides answers with the best fit to the measurement by iteratively fitting model parameters.

Relative dip or relative dip angle means the angle between the axis of the well (or the axis of the tool) and the perpendicular to the plane defined by the formation in question.

Symmetry or symmetric, as used in the present description, refers to a configuration in which the transmitter-receiver construction sets are in opposite orientations along the longitudinal axis of the instrument (eg, θ, 180-θ), so that said transmitter-receiver sets can be are correlated during the usual symmetry operation (for example, transfer, specular reflection, inversion and rotation) with respect to a point on the tool axis or a symmetry plane perpendicular to the tool axis. Symmetrization means a procedure in which the responses of symmetrical components are added or subtracted to obtain a combined response.

The front surface of the tool means the angular orientation of the tool along its longitudinal axis, the opposite angle between the selected mark on the tool body (for example, a drill collar) and either the top of the borehole wall and the geographic north.

SUMMARY OF THE INVENTION

In one aspect of the present invention, there is provided a method and apparatus for determining dip and strike of a geological formation based on directional (i.e., azimuthal) measurements. The measurements are relatively deep so that the influence of the near-wellbore space in comparison with the well-known image sources of the well is much less significant. Another advantage is that the invention works in both conductive and weakly conductive drilling mud. The accuracy of determining the drop can be quite high (especially if the relative drop is not in the region of 90 °).

The present invention uses directional measurements with a tool based on electromagnetic (EM) waves to determine the incidence and strike of the formation bed. The azimuthal angle can be set by determining the directional response as a function of the azimuthal angle, either by real rotation of the tool, or by program rotation, using a set of triaxial coils in the case of a wireline (see, for example, US patent No. 6584408). Information about the dip is derived from the response of the symmetrized directional measurements and can be used during drilling to provide real-time tracking of the dip, but without limiting the large angles of relative dip, as in the case of known tools.

The present invention is based on the discovery that for almost all angles

- 3 006075 dip symmetrical directional responses (χζ-ζχ induction or its wave electromagnetic equivalent) are almost linearly proportional to the angle of relative dip for a given geological formation. Additionally, if the receiver and transmitter are located on opposite sides of the reservoir boundary, the proportionality coefficient is almost constant and independent of the location of the instrument. Such significant properties are true only for symmetrized measurements.

Thus, in one aspect of the present invention, it relates to a device required to perform such symmetrized measurements. This implies symmetrized pairs of TY or TYA measurements, as proposed in US Patent Application Publication No. 2003/0085707 Mteto et al., The patent holder of which is currently ZsYyetdeg. Measurements are carried out at frequencies ranging from those characteristic of the induction method to those characteristic of the electromagnetic wave method.

Another aspect of the present invention relates to a method of using the response of such a device to accurately determine both the relative fall and the azimuth of layering. True dip and azimuth can be determined from the relative dip and azimuth information associated with the orientation of the well.

Another aspect of the present invention relates to the use of such a real-time dip detection service during drilling.

Another aspect of the present invention relates to the use of such information to assist in the interpretation of resistivity anisotropy for triaxial induction instruments or electromagnetic wave instruments.

The advantage of such a fall detection over a well-known fall detection from well images includes

- high accuracy at lower relative angles of incidence;

- the availability of functions for determining the fall in real time;

- less dependence on the near-wellbore space and independence from the effects associated with lumps in the drilling fluid and filtration of the drilling fluid;

- the definition of the fall is not affected by small local variations in the angle of incidence in the areas adjacent to the wall of the well;

- the service for determining the fall does not depend on the type of drilling fluid.

Thus, the present invention can be described more precisely as a method for characterizing a subsurface formation using a logging tool located in a well passing through the formation, the logging tool having a longitudinal axis and provided with at least a transmitting system and a receiving system. The logging tool is placed inside the well so that the transmitting system and the receiving system are located in close proximity to the boundary of the studied formation, and the azimuthal orientation of the logging tool is measured. Electromagnetic energy is transmitted to the formation using a transmitting system, and signals associated with the electromagnetic energy transmitted by the used transmitting system are measured using the receiving system. The relative azimuth of the formation boundary is determined, and using the measured signals and the determined relative azimuth of the boundary, a symmetric directional measurement is formed. Then, using the formed directional measurement, the relative fall of the formation boundary is determined.

The relative azimuth and relative dip of the formation boundary can then be used to determine the true azimuth and dip of the formation boundary in a manner known in the art.

In one embodiment of the method of the present invention, the logging tool is placed on the drill string to rotate with it. This embodiment uses a transmitting system including the first and second transmitting antennas, and a receiving system including the first and second receiving antennas. The second transmitting antenna has a magnetic dipole moment, whose slope corresponds to the slope of the magnetic dipole moment of the first receiving antenna, and the second receiving antenna has a magnetic dipole moment, whose slope corresponds to the slope of the magnetic dipole moment of the first receiving antenna. At least one of the first antennas has a magnetic dipole moment inclined with respect to the axis of the logging tool, the inclined magnetic dipole moment of one of the first antennas corresponding to the first azimuthal angle. Additionally, at least one of the second antennas has an inclined magnetic dipole moment inclined with respect to the axis of the logging tool, the inclined magnetic dipole moment of one of the second antennas corresponding to the second azimuthal angle. This embodiment can be adapted to the differences between the first and second azimuthal angles. Thus, for example, the second azimuthal angle may differ from the first azimuthal angle by substantially 90 °, or the two angles may be substantially the same.

In another drill string application, the transmission system includes at least one antenna having a magnetic dipole moment inclined relative to the axis of the logging tool at an angle θ, and a receiving system including at least one antenna having magnetic dipole moment, which is inclined with respect to the axis of the logging tool at an angle of 180-θ. In this case, the transmission step and the measurement step are performed during the rotation of the logging tool together with the drill string.

In such a drill string application, the transmission system may include two spatially spaced transmission antennas, each transmission antenna having a magnetic dipole moment that is inclined relative to the tool axis by a first angle. The receiving system may include at least one receiving antenna located between the two transmitting antennas at the first depth of the well, the transmitting antenna having a magnetic dipole moment that is inclined relative to the axis of the instrument by a second angle. In this case, the transmission step includes supplying power to one of the two transmitting antennas for transmitting electromagnetic energy to the formation, while the measurement step includes measuring voltage signals associated with the electromagnetic energy transmitted by one of the transmitting antennas (using the receiving antenna) , determining the azimuthal orientation of the logging tool and rotation of the drill string so as to rotate the transmitting and receiving antennas around the axis of the logging tool. The logging tool is then moved inside the well so as to place the other of the two transmitting antennas at the first depth of the well, and power is supplied to the other of the two transmitting antennas to transmit electromagnetic energy to the formation. Then, a second voltage signal, associated with the electromagnetic energy transmitted by the other transmitting antenna, is measured using the receiving antenna, the azimuthal orientation of the logging tool is again determined, and the drill string is rotated again so as to rotate the transmitting and receiving antennas around the axis of the logging tool. Then, the relative azimuth of the boundary can be determined from the measured first and second voltage signals, and the measured first and second voltage signals can then be combined to obtain a symmetrical directional measurement.

In a drill string application according to the method of the present invention, the azimuth of a logging tool can be determined using a tool front face sensor. The relative azimuth of the boundary can be determined using binning or by correlating the measured azimuthal angles corresponding to the minimum and maximum magnitude of the measured signals.

Preferably, the measured signals are complex voltage signals. Accordingly, the necessary values of the phase shift and attenuation can be calculated from the measured voltage signals associated with the relative azimuth of the boundary. The values of the phase shift and attenuation can be obtained by taking the logarithm of the ratio of the complex voltage signals obtained for two separate preselected azimuthal angles, such as 0 and 180 ° from a certain relative azimuth of the boundary.

In a specific embodiment of the method of the present invention, the step of obtaining directional measurement includes extracting both the magnitude and phase of the measured signals by approximating the response of the measured signals for various azimuthal instrument orientations with approximating functions. The approximating functions are preferably sinusoids having approximation coefficients including constants and terms δίηφ. ω & f, δίπ2φ and ω§2f, which define an iterative approximation algorithm used to determine the azimuthal dependence of directional measurements, as described in co-filed US Patent Application No. 10/709212, filed April 21, 2004, L1 et al., and rights to which the patent holder of the present invention belongs.

In a particular embodiment of the method of the present invention, the transmitting system includes at least a first and second transmitting antenna, and the receiving system includes at least a first and second receiving antenna. The antennas are oriented in such a way that the first transmitting and first receiving antennas define the first symmetrical pair of antennas, and the second transmitting and second receiving antennas define the second symmetric pair of antennas, and the magnetic dipole moment of at least one of the antennas forms a substantially non-zero angle with logging tool.

The method according to the present invention preferably further includes the step of determining the profile of resistivity across the boundary of the formation, which may or may not be considered as part of the step of determining the fall. The resistivity profile can be determined from known data from the guide well or from resistivity measurements at the bottom of the well. Resistivity measurements at the bottom of a well are usually provided by a logging tool or other tool placed on a common tool rod with a logging tool.

The step of determining the relative dip can include the use of a pre-computed look-up table for direct measurements for the selected resistivity values of the two formation layers, separated by the boundary of the formation and the relative dip angle. By determining the true values of the resistivity of two formations in the formation, one or more pre-calculated look-up tables for the selected pair of resistivities can be used to determine the directional response of the boundary to a unit of fall corresponding to the true values of resistivity. Then, the relative drop is determined by dividing the obtained directional measurement by a scale factor, which is obtained from a specific resistivity profile by calculating the directional response of the boundary per unit of fall.

The step of determining the relative drop may further include an inversion. An example includes the steps of selecting one or more directional measurements for use in inversion, the step of selecting an appropriate inversion model, verifying that the selected inversion model is compatible with other information, and determining the relative incidence and parameters of the selected inversion model. Certain, selected parameters of the inversion model may include the position of the formation boundary and the resistivity of the formation layers on each side of the boundary. The step of selecting an inversion model includes selecting the simplest model that approximates known information, and the verification step includes comparing the selected model with known geological characteristics and other measured formation parameters.

In another application of the method of the present invention, the logging tool is a non-rotating or slowly rotating logging cable or tool located on a drill string. In a specific embodiment according to this case, the transmission system includes two transmit antennas, and each transmit antenna has a magnetic dipole moment aligned with the axis of the instrument. The receiving system includes two transverse receiving antennas with their magnetic dipole moments having different orientations, but both are perpendicular to the axis of the logging tool. Two receiving antennas are located between two transmitting antennas at a first depth of the well, essentially in the middle between two transmitting antennas.

In another embodiment of a non-rotating or slowly rotating tool, the receiving system includes a receiving antenna having a dipole moment aligned with the axis of the tool, and the transmitting system includes two pairs of transverse transmitting antennas with magnetic dipole moments in each pair having a different orientation, but perpendicular to the axis of the logging tool. A receiving antenna is located between two pairs of transmitting antennas at a first depth of the well, essentially in the middle between two pairs of transmitting antennas.

Since rotation of the tool is not possible in such applications, the rotation matrix obtained by software definition is used according to US Pat. No. 6,584,408, which also belongs to the patentee of the present invention. In such applications of the method of the present invention, without rotation or with slow rotation, the transmission step includes supplying power to one of two transmission antennas for transmitting electromagnetic energy to the formation. The measurement step involves using two receiving antennas to measure the first voltage signals associated with the electromagnetic energy transmitted by one transmitting antenna, measuring the azimuth of the logging tool, determining the relative azimuth of the boundary, and obtaining the first directionally measured voltage signal of the virtual transverse receiver with relative azimuth of the boundary using a rotation matrix corresponding to a specific relative azimuth of the boundary with respect to the azimuth of the tool. Then the logging tool is moved inside the well so as to move the other of the two transmitting antennas to the first depth of the well (where the two receiving antennas were placed), and the process is repeated. Accordingly, power is supplied to the other of the two transmitting antennas to transmit electromagnetic energy to the formation, two receivers are used to measure the second voltage signals associated with the electromagnetic energy transmitted by the other transmitting antenna, (again) measure the azimuth of the logging tool, (again) determine the relative azimuth borders. These steps make it possible to obtain a second, directionally measured voltage signal of a virtual transverse receiver with a relative boundary azimuth using a rotation matrix corresponding to a certain relative boundary azimuth with respect to the tool azimuth. The obtained first and second voltage signals of the virtual transverse receiver are then combined to obtain a symmetrized directional measurement.

In specific embodiments of non-rotational or slow-rotational applications, the transmitter system includes triaxial transmitter antennas, and the receiver system includes triaxial receiver systems. The vectors of the magnetic dipole moments of three antennas in antenna systems can be linearly independent or mutually orthogonal. Triaxial antennas can also be substantially co-located. In embodiments using triaxial antennas, the transmission step includes sequentially supplying power to each of the three transmitting antennas to transmit electromagnetic energy to the formation.

- 6 006075

In the case of mutually orthogonal triaxial antenna systems, the measurement step includes sequentially measuring the first, second and third voltage signals associated with the electromagnetic energy transmitted by the first, second and third transmitting antennas using three receiving antennas in each measurement. The voltage signals measured by the respective three receivers are then linearly combined to obtain voltages representing a pair of virtual receivers and transmitters with an arbitrary orientation. This allows one to obtain coupled voltages between three mutually orthogonal virtual receivers and transmitters and a composition of symmetrized directional measurement using coupled voltages for symmetric pairs of the receiver and transmitter.

The relative azimuth of the boundary can be determined in such embodiments by 1; · ιη ^-ι (ΥΖ / ΧΖ) or ίαη ^-1 (2 * ΧΥ / (ΧΧ-ΥΥ)), where ΥΖ is the voltage for the dipole magnetic moment of the receiving antenna oriented Υ, and transmitting antenna oriented in по,

ΧΖ is the voltage for the dipole magnetic moment of the receiving antenna oriented in X, and the transmitting antenna oriented in Ζ,

ΧΥ is the voltage for the dipole magnetic moment of the receiving antenna oriented along Χ and the transmitting antenna oriented along Υ,

ΧΧ is the voltage for the dipole magnetic moment of the receiving antenna oriented along Χ and the transmitting antenna oriented along Χ,

ΥΥ is the voltage for the dipole magnetic moment of the receiving antenna oriented along Υ and the transmitting antenna oriented along Υ,

Ζ is the direction along the axis of the tool,

X is the direction along the reference azimuthal angle and perpendicular to Ζ,

Υ is perpendicular to X and Ζ; and

Χ, Υ, Ζ form a Cartesian coordinate system.

Directional measurements according to such an embodiment can be obtained using the associated voltage Χ'Ζ-ΖΧ ', where X' is the direction in the relative azimuth of the boundary and perpendicular to the оси axis of the tool.

In the case of a linearly independent triaxial antenna system, the signals of a pair of virtual transmitters with a fixed orientation are generated from the measured first, second and third voltage signals using a three-dimensional rotation matrix corresponding to a fixed orientation.

Another aspect of the present invention relates to a method for characterizing a subsurface formation and includes the steps of placing the logging tool inside the well so that the transmitting system and the receiving system of the tool are located in close proximity to the boundary of the formation being studied and measuring the azimuthal orientation of the logging tool. Electromagnetic energy is transmitted to the formation using a transmitting system and signals associated with the electromagnetic energy transmitted by the transmitting system are measured using the receiving system. Using the measured signals, a symmetric directional measurement is obtained, and a specific directional measurement is constructed as a function of depth for many different depths. The depth at which at least one of the upper and lower antennas crosses the formation boundary can then be identified using the discontinuity in the rate of change of the directional measurement.

Another aspect of the present invention relates to a logging device for characterizing a subsurface formation through which a well passes, including a housing configured to move in a well having a longitudinal axis. The housing of the logging device can be made with the possibility of movement and rotation in the drill string and move using a logging cable. To transfer electromagnetic energy to the formation, a transmission system is placed in the housing. To measure signals associated with electromagnetic energy transmitted by a transmitting system, a receiving system is placed in the housing. Means are also provided for determining the relative azimuth of the formation boundary that is of interest in the immediate vicinity of the well to obtain a symmetrical directional measurement using signals measured by the receiving system and the relative azimuth of the boundary determined by means of determining the azimuth, and for determining the relative dip of the formation boundary, using the resulting directional measurement.

In a specific embodiment of the device of the present invention, the transmitting system includes at least one antenna having a magnetic dipole moment inclined relative to the axis of the logging tool by an angle θ, and the receiving system includes at least one antenna having a magnetic dipole moment inclined relative to the axis of the logging tool at an angle of 180-θ.

In yet another embodiment of a device of the present invention, a transmission system

- 7 006075 includes at least a first and a second transmitting antenna, and a receiving system includes at least a first and a second receiving antenna. The antennas are oriented so that the first transmitting and first receiving antennas form a first pair of symmetrical antennas, and the second receiving antenna form a second pair of symmetrical antennas.

In yet another embodiment of the apparatus of the present invention, the transmitting system includes two transmitting antennas, each transmitting antenna having a magnetic dipole moment aligned with the tool axis. The receiving system includes two transverse, mutually perpendicular receiving antennas, and two receiving antennas are located between two transmitting antennas. Alternatively, the device may be configured with a reverse arrangement of receivers and transmitters (two transmit antennas are located between two receive antennas).

In a specific embodiment, the transmitting system includes triaxial transmit antennas, and the receiving system includes triaxial receiving antennas.

The azimuth determination means may include a tool front surface sensor and / or a carrier readable by a computer with computer-executable instructions for determining the relative azimuth of the boundary of the formation being studied.

In one embodiment, the forming means includes a medium readable by a computer with computer-executable instructions for generating a symmetric directional measurement using signals measured by the receiving system and a relative boundary azimuth determined by means of determining the azimuth.

The means for determining the relative dip can include media readable by a computer with computer-executable instructions for determining the relative dip of the formation boundary using the generated directional measurement.

Brief Description of the Drawings

In order that the above distinguishing features and advantages of the present invention can be understood in more detail, a more specific description of the present invention, briefly summarized above, can be given with reference to embodiments of the present invention, which are illustrated by the accompanying drawings. However, it should be noted that the accompanying drawings illustrate only typical embodiments of the present invention and, therefore, should not be construed as limiting its scope, since the present invention may allow other equally effective embodiments of the present invention.

FIG. 1 is a schematic view of induction tools or electromagnetic wave tools of the prior art;

FIG. 2A and 2B are vertical cross-sectional views showing eddy currents induced by a logging tool in a well that travels through a formation without a relative dip and a relative dip, respectively;

FIG. 3 is a vertical sectional view of a prior art rotary drill string with which the present invention can be applied to improve;

FIG. 4 is a schematic view of a main logging tool for directional measurement having a pair of symmetrical transmit and receive antennas;

FIG. 5 depicts a schematic view of a directional measurement logging tool located in a segment of a well that lies within a single formation in the case where symmetrized directional measurements are not susceptible to a drop in α and anisotropy;

FIG. 6 is a schematic view of a directional logging tool located in a segment of a well that crosses a boundary of a formation passing through two formations in a case where symmetrized directional measurements are practically constant and proportional to the drop for a given resistivity profile if the transmitter (s) and receiver (receivers) are located on opposite sides of the reservoir boundary;

FIG. 7 is a resistivity diagram describing a unit boundary of a formation that separates two adjacent formations of a formation;

FIG. 8A-8C show diagrams characterizing formation responses (known resistivity measurements and symmetric directional measurements) to electromagnetic energy transmitted by a logging tool oriented along the axis of the tool well, the logging tool having antennas located on each side of the boundary;

FIG. 9 depicts a response to symmetrized directional signals for an electromagnetic wave method, given as a function of true vertical depth (IHG) for various dip angles when crossing a formation boundary, in accordance with one aspect of the present invention;

FIG. 10 depicts a response similar to that of FIG. 9, but the signals for the electromagnetic wave method are normalized by the angle of incidence on a logarithmic scale;

FIG. 11 depicts a normalized response similar to that of FIG. 10 on a linear scale;

FIG. 12 depicts a response similar to that of FIG. 9, but representing a unit

- 8 006075 a pair of transmitter-receiver (Prdprm) before symmetrization;

FIG. 13 depicts a response similar to that of FIG. 10, but representing two co-located pairs of PrdPrm;

FIG. 14 shows the response equivalent of an induction tool for a symmetrized pair of PrdPrm (ΧΖ-ΖΧ measurement) normalized by the angle of incidence;

FIG. 15 is a flowchart of a fall detection procedure according to one aspect of the present invention.

Detailed Description of a Preferred Embodiment

In FIG. 3 shows a prior art rotary drilling rig and drill string in which the present invention can be applied for improvement. The surface platform and drill rig 10 are located above the borehole 11 passing through the subsurface formation P. In an illustrative embodiment of the invention, the borehole 11 is formed by rotary drilling in a manner well known in the art. It will be apparent to those skilled in the art, however, that the present invention is also applicable in directional drilling as well as in rotary drilling, and is not limited to surface drilling rigs. It is also apparent that the present invention is not limited to applications during drilling, but can also be used in wireline applications (as further described below).

The drill string 12 is located inside the borehole 11 and includes a drill bit 15 at its lower end. The drill string 12 is rotated using a rotary table 16, driven by means (not shown), which engages with the lead pipe 17 at the upper end of the drill string. The drill string 12 is suspended on a hook 18 attached to a tackle block (also not shown) through a lead pipe 17 and a swivel 19, which allow rotation of the drill string relative to the hook.

Drilling fluid or mud 26 is stored in a reservoir 27 formed at the drilling site. Pump 29 delivers drilling fluid 26 to the interior of drill string 12 through a port in swivel 19, causing the drilling fluid to flow downward through drill string 12, as indicated by arrow 9. The drilling fluid exits drill string 12 through the ports in drill bit 15 and then passes up through the area between the outside of the drill string and the borehole wall, called the annulus, as shown by arrows 32. In this case, the drilling fluid lubricates the drill bit 15 and transfers the fragments of the formation up to the surface in the process e his return to the reservoir 27 for cleaning.

Drill string 12 further includes a bottom hole system (BSC), generally designated 34, located near drill bit 15 (in other words, within a few drill collar lengths from the drill bit). The bottom hole system includes means for measuring the processing and storage of information, as well as communication with the surface. The bottom hole system 34 thus includes, in addition to other elements, a measurement and local communication device 36 (communication device) for detecting and transmitting the resistivity of the formation P surrounding the well 11. The communication device 36, also known as the resistivity logging device, includes the first pair of transmitting / receiving antennas Prd, Prm, as well as the second pair of transmitting / receiving antennas Prd ', Prm'. The second pair of antennas Prd, Prm is symmetrical with respect to the first pair of antennas Prd, Prm, as described below. The resistivity logging tool 36 further includes a controller for controlling data collection, as is known in the art.

SNSC 34 additionally includes tools located inside the collars 38, 39 of the drill for performing various other measuring functions, such as measuring natural radiation, density (using gamma or neutron radiation) and the pore pressure of the formation R. At least several of the collars of the drill equipped with stabilizers 37, which is well known in the art.

A surface / local communication unit 40 is also included in the SNSC 34 immediately above the drill collar 39. Block 40 includes a toroidal antenna 42 used for local communication with resistivity logging device 36 (although other local communication tools may be used to improve), and a known type of acoustic telemetry system that communicates with a similar system (not shown) on the surface earth through signals carried in a drilling fluid or fluid. Thus, the telemetry system in block 40 includes an acoustic transmitter generating an acoustic signal in the drilling fluid (otherwise referred to as hydraulic pulse), which represents the parameters measured in the bottom of the well.

The generated acoustic signal is received on the surface of the transducers, denoted by reference numeral 31. Transducers, such as piezoelectric transducers, convert the received acoustic signals into electrical signals. The output of the transducers 31 is connected to the receiving subsystem 90 located at the wellhead, which demodulates the transmitted signals. The output of the receiving subsystem 90 is connected to the computer processor 85 and the recording device 45. The processor 85 can be used to determine the profile of the formation resistivity (among other things) in real time during logging or subsequently by extracting recorded data from the recording device 45. The computer processor is connected to a monitor 92 using a graphical user interface (GUI), through which the parameters measured in the bottom of the well and the specific results obtained from them (for example, pros resistivity) are presented to the user in graphical form.

The transmitting system 95, located near the wellhead, is also provided for receiving input commands from the user (for example, via the GUI of the monitor 92), and is configured to selectively interrupt the pump 29 in a way that can be detected by the transducers 99 in block 40. In this way, a two-way communication between block 40 and equipment located near the wellhead. A suitable block 40 is described in more detail in US patent No. 5235285 and 5517464, the rights to which belong to the patent holder of the present invention. It will be apparent to those skilled in the art that other acoustic methods can be used to communicate with the surface, as well as other telemetry tools (e.g., electromechanical, electromagnetic).

Two types of coil antennas are used to form direction-sensitive measurements. For one of the types, directional sensitivity is achieved either by displacing the antenna, for example from the center of the longitudinal axis of the logging tool, or by partial shielding. Directional measurements can also be carried out using at least one antenna located so that its magnetic dipole moment is not aligned with the longitudinal axis of the instrument carrying the antenna. The present invention relates to a second type of direction-sensitive antennas.

In FIG. 4 schematically shows the main resistivity logging device 36 for directional measurement using electromagnetic (EM) waves. The device includes a transmitting antenna Prd, which emits EM waves of a certain frequency Г, and a receiving antenna Prm, which is at some distance b to the side. Also shown is a symmetric pair (Prd ', Prm') according to the publication in the application for US patent No. 2003/0085707 (McLoe and others), the rights to which belong to the patent holder of the present invention. For clarity and simplicity, the following discussion is limited to the transmitting antenna Prd and the receiving antenna Prm, although, in the general case, it is applicable to a symmetrical pair of antennas Prd 'and Prm'. It should be noted that, although the inclined dipole moments of two symmetrized pairs are shown to be located in the same plane in FIG. 4, this is not required in the present invention. As is clear from the discussion that follows, the signals from two pairs having dipole moments in different planes can be summed to obtain equivalent results if the selected coefficients or phase shift in direction or attenuation are used in the symmetry operation.

In operation, the receiving antenna Prm registers the voltage in U _ct induced by the EM wave from the transmitting antenna Prd and its secondary currents induced in the formation through which the well containing the device 36 passes resistivity logging. Both antennas Prd and Prm are fixed on the device 36, the resistivity logging and, therefore, physically rotate with the device. This is in contrast to an alternative well logging application of the present invention in which virtual antennas rotate using software tools (i.e., the measured voltage signals rotate around the axis of the logging tool into a plane that is perpendicular to the boundary under study using a rotation matrix corresponding to a certain boundary azimuth )

The resistivity logging device 36 is provided with a front-side sensor inside one of the drill collars 38, 39 for continuously indicating the azimuthal orientation of the resistivity logging device, and a controller for controlling the first and second pairs of receiving and transmitting antennas so as to selectively transmit electromagnetic energy to the formation and measure voltage signals associated with transmitted electromagnetic energy as a function of the azimuthal orientation of the logging tool. The front of the logging device uses one of the following: magnetometers to indicate the azimuthal orientation of the logging device relative to the magnetic north of the Earth; gravity sensors to indicate the azimuthal orientation of the logging device relative to the Earth's gravity vector; or other suitable means known in the art. It can be assumed that the antenna orientation forms angles of 0 _t for the transmitting antenna Prd and θ _κ for the receiving antenna Prm. The azimuthal changes in the associated voltage during rotation of the tool can be expressed in terms of the relationship of the Cartesian components of the magnetic dipole moments in the idea

- 10 006075

RlDL-P ' »+ | (E + _I ^) 5111 ^ (71¾] + _{1' ztθ _T soz₽ _I + K _n with $ ^ 1pv _l] + cos [And ϊίηθ _τ ¢ 03¾ + αχθ _τ ztdTsztψ i | (E _x + ^) nn ^ 51n ₽ _n ] nn2 ^ + [| (Г „-Κ„,) 3Ϊη ^ .βίηβ _Λ ] <»52 ^ = С ₀ (б _г , в _([ ) + С .. _{1 ((^ (1)} cos + C _{|. 1} (^, b _l) sin ^ 4 ^€, 1 _C (^, ^) so52 (<+ C _r1 (^, ^) sin2 ^. (1.1) where the set of complex coefficients С _о , Сю, Сю, С ₂ s, С _{23 is} defined to represent the amplitudes of various components, the measured response of the formation. Accordingly, complex coefficients are defined as <ζ (^ · Λ) · ίΕ ₌ <»» ^ α> 80 _Λ + | (Г _Л + ^) 3111 ^ 5171¾] ^ (¾ .¾) = [Ц, 5111¾ 003¾ + Г ₌ ¢ 05 ^ (7) ¾] ^ (¾.¾) = 510¾ 005¾ + ^ ¢ 05¾ 510¾]

- ^) 510¾ ^ ¾] ^, (¾.¾). [1 (Г „+ ^) 31.1¾ 310¾] (1.2)

According to one aspect of the present invention, it has been found that these coefficients are functions of the formation resistivity, wellbore deviation, and azimuth angle at the tool location. In the operation of symmetrization, i.e. (θ _τ <=> θ _Ε ), expression (1.1) is simplified to

W =

2 [And _P- T _and ] zt (0 _g - ^) "" ^ + 2 [And _I - KD 3111 (¾ -0 _Λ ) 8ίη "ί = С _к (in _g , 0 _l ) SOP ^ +0, , (¾. ^ _D) 5SH (Q (1.3)

All second-order harmonics (C ₂ s, C ₂₃ ) disappear after subtraction, since they are symmetric with respect to replacing the tilt angles of the transmitter and receiver. Thus, symmetrization simplifies the azimuthal variation of antisymmetric signals.

At this stage, the reference point of the azimuthal angle is arbitrary. For plane geometry, if we choose the reference point of the angle φ as the direction of the projection of the normal vector to the layering plane on the plane of the tool, we obtain ν _γζ = ν _ζγ = 0 by the symmetry condition and K (¢) will have a pure dependence like soff. However, having determined any reference, the layering orientation can be calculated as] = 1ap '[

(1.4)

When turning, fi _e <b is the normal to layering and, therefore, qda is exactly [ν _{γζ -ν ζγ} ] without taking into account the multiplicative constant 2δίη (θ _τ -θ _κ ).

After determining the voltage at each receiving coil associated with the transmitting coils, a complete measurement can be determined: by adding the voltages in the case of an induction tool or by finding the complex voltage ratio in the case of an electromagnetic wave tool. For example, for the electromagnetic wave logging device of FIG. 4, the absolute value of the voltage in each receiver can be obtained as the square root of the sum of the squares of the real and imaginary parts of the complex voltage (equation 1.1), and the ratio of the absolute values gives the attenuation from which the resistivity K _ai determined by attenuation (resistivity) can be obtained formations at a relatively large depth of study around the receivers). The phase for each receiver is obtained as the arctangent of the ratio of the imaginary and real parts of the complex voltage, and the phase shift is the phase difference in the two receivers. After this, the resistivity K _p8 determined by the phase shift (resistivity of the formation at a relatively shallow depth of study around the receivers) can be obtained.

For measurements of the electromagnetic wave method, the voltage logarithm difference (or ratio) of two measurements is obtained. Following the instructions of McLoe et al., We take the amplitude of the azimuthal response, i.e. the difference in the phase shift and attenuation of the measurement, at the angles f and (f + 180), estimated for the maximum voltage response. From equations (1.1-2), this leads to the approximation

-11 006075 _ s „<^ _r ,) 4Г _1С (¾, ¾) soya4 + С _1; (¾,) 81П 4 ^ (¾, ¾) soy 24 + С _b (¾, ¾) 81П 24 'у у (180 + 4) С _е (иг .0,) -С _к (^ .¾) ооз 4 -C _and (θ _τ , (9 _L ) 5SH 4 + C _2. (6 " _r , ¾) cos 24 4C _b {θ _τ , in„) rt 24 ζίι 2

C ”(¾, 6c)) Cu 24 + C _{2 /} (6 _T , 6 _H ) 5ΪΠ 24 [And 31P П -003 ^ - + Г СО50-3ί» θ „] 005 4 + {K 51P 6- POP 6 * + And soR_5ίη ^ _15ίη 4 ΛΖ * K Π ί .K $ Σ I K Tu ί Λ ” _{ι + 2} - - ⁽ _a ^st ^ G ^{co1> e} A ⁺ 2 ^ίΚ χχ ⁺ ^ VU ¹⁵ ' ^{P &} T ^{n &} I ⁺ 2 ^[[ί 2 ^»+ Ά ^{'1 δίΠ5ίη +} 2 ^{[% V} yy ^{1h' pθ} Τ ^{ίία &} Κ ⁰⁰⁸ (1.5)

Maximum | Y | is achieved at φ = 0 if x is chosen as the direction coinciding with the layering normal. When evaluating at an angle φ = 0, equation (1.5) gives ^Я JT ⁽⁰⁾ _q ! _{+ 2} 0, (^, ^) ^ (¾.¾)

Г _ЛГ (180) 0 (^, ^) ^ (¾.¾) [К 5ш £ -СО8 # _п + и СОЗ ^ -Т / мб'п]., D, 2 χζ Т Я ζχ Т д ~ V СОЗ POPs 6 * +7 βϊηβ-ίίη ^ ο

ΖΖ l K XX 2 l (1.6)

However, this is still not a pure χζ-ζχ type response, which is required, i.e. which is insensitive to layering anisotropy and angle of incidence.

The present invention relates to directional measurements that are insensitive to formation anisotropy over a wide range of incidence angles and over a wide frequency range. Now, after the symmetrization procedure (θ _τ <=> θ _κ ) according to Mscheto et al.

MOL) G _lg (180LL) _{ax + 2} [G _d -G _d ] 3g (6> -6b)

7 ^ (180,0 ^, ¾) 7 ^. (0, ¾.¾) 7 ^ .0050 ^, 0080 ^ + 7 ^ 81 110 ^ 51110 ^ (1.7).

Again, this is close to an induction-type answer, although the denominator still contains some components that do not have a simple dependence on [χζ-ζχ]. This proves that the symmetrization procedure for measuring the electromagnetic wave method can give responses similar to those for the symmetrized measurements of the induction method, but which are not clean. It is also true that measurements of the electromagnetic wave method can be carried out with two arbitrary orientations for an azimuthal response.

Thus, the layering orientation is determined by studying the azimuthal dependence of the response of the logging device. One method for extracting various azimuthal response components (i.e., coefficients) is described in U.S. Patent Application, L1, et al. filed April 21, 2004, serial number 10/709212, in which the measured azimuthal changes in the signal are approximated by approximating functions. In particular, the azimuthal response is approximated according to the extracted relevant terms 51i and the juice of the directional measurements, which is performed iteratively. Such an approximation algorithm is performed by a digital signal processor using an integer algorithm so that it is fast enough to execute for all channels within a sampling period of 4 ms. The accurate use of azimuth angle information and the randomization of input sequences makes the algorithm resistant to irregular tool rotations, as well as to spasmodic movement under severe drilling conditions. In this case, all the data is used to obtain the upper / lower signal instead of data on only two sites, thereby improving the signal-to-noise ratio of the measurement. The use of precise azimuthal nodes also makes the determined layering orientations more accurate.

A detailed algorithm can be described as follows.

Floating-point implementation: starting from the initial value of the matrix P ₀ and the vector and ₀ , then we pass to the algorithm described below with the measurement y (φ,) and the basis r = (1 soff, κίηφ, sok2f, §ίη2φ ₁ ) ^τ , where P is a matrix of dimension MxM, and u and r are vectors of dimension M. M is the dimension of the basis function. After the Ν-th iteration, it is converted to a value that represents the coefficients of the expression. This algorithm is stable, and convergence is usually achieved after 10-15 iterations.

A detailed algorithm is given below.

- 12 006075

P, <- P-. ~ TShaNge P _o at! and ₀ ; Wag t = 1 ίο Matr.

Ry-1 ' ^G l, -1' ^G "-1 * RP-1

1 + A | -1 ’L> _ |

from. + -and _m _, -P „· /;.,. (y,., -Ζ7Γ1 - <. Л„ -ΐ ^g .

pen t; ge (um (1G) ‘, where N 5ashr1s5 is the total number of samples taken per cycle,

M is the dimension of the vector of approximating functions (the number of approximating functions), and is the vector of approximating coefficients of dimension M,

In is a vector of values of the approximating functions in each position of the measurement of size M and

P is a matrix of dimension MXM.

In many cases, a floating point implementation may be too costly to run on currently available CPUs located in the bottom of the well, and there may be hundreds of channels for approximation, and the data input for each azimuth angle should be quite short (ms) for so that the angle is accurate at a higher rotation speed. In such a situation, an integer implementation with some modifications may be used to improve accuracy (for example, using 32 bits when multiplying) by zooming to prevent overflow and to speed up the conversion. The values of the basis function can also be pre-generated and stored in memory so that they can later be interpolated to obtain values for the true angle φ ₁ .

Since the approximation method extracts only the relevant signals, only the coefficients used need to be stored. Thus, in this case, it is required to save only 5 coefficients, compared to 32 if it is necessary to group all the data using the example with 32 sites. Specialists in the art will appreciate the advantages of the method of the present invention, which includes the accuracy of the extracted signals and a specific improvement in the accuracy of the azimuthal angle.

From these approximation coefficients, the azimuthal angle (strike) of the layering boundary can be determined.

FIG. 5 is a schematic representation of a directional logging device 36 ′ having an axis BA and located in a well segment 11 that lies within one formation formation B ₂ . Stratum B ₂ is separated from the overlying stratum B _{1 by the} boundary P ₁ , and is separated from the underlying stratum B3 by the boundary P2. proved that in such a configuration symmetrized directional measurements obtained from the ligament ₁ -Prm Tx ₁ and Tx ₂ -Prm ₂ (according to Miller et al.) are insensitive to α anisotropy and dip.

However, in FIG. Figure 6 shows a configuration where such directional measurements are extremely sensitive to falling. Thus, FIG. 6 is a schematic representation of a directional measurement tool 36 having an axis BA and located in a well segment 11 ′ intersecting a formation boundary P ₁ . Well 11 'passes through two formations B ₁ , B _{2 of the} formation, and the logging device is configured (and located) so that the transmitter Prd! and the receiver Prm ₂ are located on opposite sides of the border P ₁ . With this arrangement, the symmetrized directional measurements obtained by tool 36 are practically constant and proportional to the drop for a given resistivity profile.

FIG. 7 is a resistivity diagram describing the axis BA of a well segment intersecting one boundary P _{1 of a} formation that separates two adjacent formations B _b B _{2 of the} formation. In this example, adjacent formations of the formation show a transition resistivity of 21/1 Ohm-m across the boundary of P ₁ and a drop of α = 5 °.

In FIG. 8A-8C are diagrams showing formation responses to electromagnetic energy transmitted by a logging device oriented according to FIG. 7, with the logging device antennas located on opposite sides of the border P ₁ (similar to FIG. 6). Thus, FIG. 8A describes a resistivity profile determined in a known manner through formations B !, B ₂ . FIG. 8B, 8C describe attenuation and phase shift, respectively obtained from symmetrized directional measurements with antennas located across the formation boundary (as in FIG. 7). Accordingly, parts of the curve diagrams in FIG. 8B and 8C, which are substantially constant (i.e., substantially flat lower segments), represent measurements made when the antennas are located on opposite sides of the P1 boundary.

It was found that the symmetrized directional response is insensitive to the angles of incidence and anisotropy for large relative angles of incidence (for example,> 60 °) and if both the transmitter and the successor are located on one side of the boundary (see Mt. .). For smaller relative drops (for example, <40 °), it turned out that the response of a symmetric directional measurement (of the χζ-ζχ type) is directly proportional to the angle of relative fall, if the transmitters and receivers are on opposite sides of the boundary, as will be described below.

In FIG. Figure 9 shows the response of the directional signal for the electromagnetic wave method at 100 kHz, shown as a function of the position of the instrument according to the true vertical depth (IVG) when moving from the formation from 1 Ohm-m to the formation from 10 Ohm-m. The signal gradually increases with an increase in the angle of relative incidence. At zero relative incidence, there is no change in the signal coming from the structure when the tool rotates due to symmetry. Thus, the signal is zero. However, as soon as the relative drop becomes non-zero, a final signal is generated. In fact, as can be seen from the diagram, even with a relative drop of 1 °, the phase shift signal is slightly higher than 1 °, which is quite significant, bearing in mind the measurement accuracy that can be achieved with. help existing electronic tools.

In FIG. 10 shows the same response as in FIG. 9 for relative dip angles up to 30 °, but with phase shift and attenuation signals normalized to the relative dip angle. Normalized curves converge on top of each other regardless of the angle of incidence. This is especially true in the middle when the transmitter and receiver are on opposite sides of the formation boundary. This means that the phase shift and attenuation signal from the symmetrized response are linearly proportional to the angle of incidence, and this proportionality coefficient is practically independent of the position of the instrument when Prd and Prm are on opposite sides of the boundary. Of course, the linearity factor depends on the location of the PrdPrm, the measurement frequency and the resistivity of the two layers - mainly on the magnitude of the part of the two layers with the highest conductivity.

The response angle normalized by the angle of incidence measurements for 100 kHz are again shown in FIG. 11, including angles up to 70 ° on a linear scale. The scaling factor for a 50 ° phase shift is 2% less, and for 70 ° it is 6% less than for smaller phase shift angles. Attenuation is more sensitive, showing changes of 15 and 40% at 50 and 70 °, respectively.

It is important to note that such simplicity of response is a direct result of symmetrization. In FIG. 12 shows the response for individual pairs of PrdPrpmr before symmetrization in exactly the same configuration as in FIG. 9. The responses are much more complex. The linear relationship between the measured signals and the dip of the formation, which we clearly saw for the symmetrized PrdPrm configuration, is no longer observed. Symmetrization simplifies the response of the tool to the reservoir boundary in wells with a large angle and does the same for dip sensitivity. This phenomenon is based on physical laws.

FIG. 9-12 illustrate the response for pairs of PrdPrm antennas physically located in different places, although the distance of PrdPrm is fixed for two pairs, as required for symmetrization. In FIG. 13 shows the normalized response for two co-located pairs of PrdPrm. This is intended to make a comparison with FIG. 10. The response from co-located and separately located pairs of PrdPrm to the fall is quite similar.

In FIG. 14 shows the equivalent response of an induction tool (χζ-ζχ) of symmetric pairs at 10 kHz, normalized to the angle of visible incidence. Both the real and imaginary parts of the receiver voltage can be scaled as a drop with a very good approximation. The proportionality coefficient is almost constant for the real part of the voltage and varies linearly with distance when the pair of transmitter and receiver is located on two sides of the interface.

The simple connection of the symmetrized directional response with the relative dip allows you to accurately determine the relative dip and azimuth of the layered structure. For example, when falling = 1 °, the phase shift signal according to FIG. 9 is about 0.09 dB and 1.6 °. Even by electronic means, phase shift and attenuation can be measured up to 0.02 ° and 0.004 dB, respectively. This means that the drop can be measured with an accuracy of 0.01-0.03 °, if such accuracy is required, in which case very accurate sensors must be used. As a comparison, this level of accuracy is two orders of magnitude less than that which the well image tools of the prior art can provide. More realistically, given the possible effects of the environment, it is possible to measure the relative drop with an accuracy of 10% even at very small angles of relative drop.

After determining the relative fall, the directional response can be used to derive an estimate of the distance to the border if the sensors are away from the border.

It is also interesting to note the radical difference between the response of the instrument when the receivers and transmitters are located on opposite sides of the boundary, and such when both the transmitters and receivers are on the same side. The slope of the responses, as a function of depth, changes dramatically when crossing. This change can be used to accurately identify the position of the formation boundary.

This method is applicable both to induction tools on a logging cable, and to electromagnetic wave tools for logging while drilling (L ^ E), regardless of the method of movement. For applications during drilling, this information can be obtained in real time by sending measurements to the wellhead and analyzing them on the surface, or by analyzing data in the bottom of the well first and then sending information about the structure of the fall to the surface.

It will be apparent to those skilled in the art that although the response depends on layering properties, such as resistivity, it also depends on the location of the transmitter-receiver and frequency.

A separate aspect of the present invention will be described below with reference to FIG. 15. Perform directional measurements in real time, determine the azimuth of the boundary of the formation, and form directional measurements (all as described above) using a logging device located in the well in the immediate vicinity of one or more of the studied formations (step 110).

The formation resistivity is determined on each side of the identified boundary using standard resistivity, induction, or electromagnetic wave measurements (step 105). Selected directional channels from the input directional voltage signals are used to accurately determine the angle of incidence and the position of the boundary. The determined angle of incidence can be checked using various directional channels from the inputted directional voltage signals, using a lookup table or using inversion methods (step 120). A simple procedure for a chart or look-up table is prepared initially to determine the fall of one border.

A symmetric measurement response is generated, and this response is scaled based on known resistivities to predict the angle of incidence of the formation in question (i.e., the boundary of the formation). The scaling step corresponds to (determining) the scaling factor. The boundary of the formation in question is identified by moving the logging device inside the well, generating new directional measurements and a symmetric response, scaling the symmetric response, and observing the response changes (step 120).

In one embodiment, the step of determining apparent fall is carried out using a lookup table. In this case, the method further includes the steps of determining the scaling factor for the selected pair of specific resistivities by calculating the directional response of the boundary per unit of incidence, determining the relative incidence by dividing the generated directional measurement by the scaling factor and using the lookup table for the selected resistivity pairs and determining relative fall and azimuth to determine the true fall. A lookup table can be pre-computed for many resistivity pairs. Then, from the obtained resistivities, we can easily find from the table how many units (degrees, dB or volts) we have per degree of drop. An alternative is to build a 3-dimensional look-up table, which includes falls, and apply a simple procedure to the look-up table.

Alternatively, the scaling factor is determined from a specific resistivity profile by calculating the directional response of the boundary per unit of incidence, and determining the relative incidence by dividing the generated directional measurement by the scaling factor.

In another embodiment, the step of determining the relative fall includes inversion. The inversion preferably includes the steps of selecting one or more directional measurements for use in the inversion, selecting the appropriate inversion model, verifying that the selected inversion model is compatible with other information, and determining the incidence and parameters of the selected inversion model. Certain parameters of the selected inversion model preferably include the position of the formation boundary and the formation resistivity on each side of the boundary.

The step (125) of selecting or constructing a model preferably includes selecting the simplest model that matches the known information and creating a visualization of the selected directional measurements. The step of selecting models preferably further includes the use of algorithms to reduce the complexity of the model, such as the Akaike information criterion. The inversion based on the model must be flexible, allowing the choice of parameters from 1 (only fall) to 6 (fall, position of the boundary and anisotropic resistivities of the two layers). The process may be interactive or in the form of batch processing. A model-based inversion can be used for one or more boundaries (an arbitrary resistivity profile).

Those skilled in the art will appreciate that the present invention can be implemented using one or more suitable general purpose computers having suitable hardware and programmed to perform the procedures of the present invention. Programming can be performed using one or more program storage devices read by a computer and encoding one or more programs composed of instructions executed by a computer to perform the operations described above. A program storage device may be in the form of, for example, one or more floppy disks; SE-K.OM or other optical disc; magnetic tape; read-only memory (ROM); or other means well known in the art, or subsequently developed. A program composed of instructions may be object code, i.e. in binary form, which is more or less directly executed by a computer; source code requiring compilation or interpretation before execution; or some kind of intermediate form such as partially compiled code. The exact appearance of the program storage device and instruction encoding is not important for the present description. Thus, these processing means can be implemented in surface equipment in a tool or shared between them, as is known in the art. It is also apparent that the methods of the present invention can be used with any type of well logging system, for example, wireline tools, logging tools while drilling / measuring while drilling, or logging tools while raising the drill string.

From the above description, it is understood that various modifications and alterations can be made in the preferred and alternative embodiments of the present invention without departing from the true spirit of the invention.

This description is for illustrative purposes only and should not be construed as limiting. The scope of the present invention should be determined only by the following claims. The term “included in the claims” means at least so that the listed list of elements in the claims is an open group. One and other terms denoting singularity include their plural forms, unless they are expressly excluded.

Claims (32)

CLAIM 1. A method for describing a subsurface formation with a logging tool located in a well passing through the formation, the logging tool having a cylindrical shape and provided with at least a transmitting system and a receiving system, this method includes the steps of placing the logging tool inside the well in this way that the transmitting system and the receiving system are located in close proximity to the boundary of the formation in question; measuring the azimuthal orientation of the logging tool; transmitting electromagnetic energy to the formation using a transmission system; measuring signals associated with electromagnetic energy transmitted by the transmitting system using the receiving system; determining the relative azimuth of the formation boundary; forming a symmetrized directional measurement using the measured signals and a certain relative boundary azimuth; and determining the relative dip of the formation boundary using the generated directional measurement. 2. The method according to claim 1, which further includes the steps of determining the true azimuth and true fall of the formation boundary. 3. The method according to claim 1, in which the logging tool is located in the drill string, for rotation with it; a transmitting system includes a first and second transmitting antenna and a receiving system includes a first and second receiving antenna; moreover, the second transmitting antenna has a magnetic dipole moment with a slope corresponding to the slope of the magnetic dipole moment of the first receiving antenna, and the second receiving antenna has a magnetic dipole moment with a slope corresponding to the slope of the magnetic dipole moment of the first receiving antenna, so that at least one of the first antennas has an inclined magnetic dipole moment with respect to the axis of the logging tool, and the inclined magnetic dipole moment of one of the first antennas corresponds to vomu azimuthal angle, and at least one of the second antennas has a tilted magnetic dipole moment with respect to the axis of the logging tool, the oblique magnetic dipole moment of one of the second antennas corresponding to the second azimuthal angle. 4. The method according to claim 1, in which the logging tool is located in the drill string, for rotation with it; the transmitting system includes at least one antenna having a magnetic dipole moment inclined with respect to the axis of the logging tool by an angle θ; the transfer stage is carried out during the rotation of the logging tool together with the drill string; - 16 006075 the receiving system includes at least one antenna having a magnetic dipole moment inclined relative to the axis of the logging tool at an angle of 180-θ; and the measurement steps are carried out during the rotation of the logging tool together with the drill string. 5. The method according to claim 4, in which the relative azimuth of the boundary is determined by correlating the measured azimuthal angles corresponding to the minimum and maximum magnitude of the measured signals. 6. The method according to claim 1, in which the step of forming a directional measurement includes extracting both the magnitude and phase of the signals by approximating the response of the measured signal for various azimuthal instrument orientations by the approximation functions. 7. The method according to claim 1, in which the transmitting system includes at least a first and a second transmitting antenna; a receiving system includes at least a first and a second receiving antenna; moreover, the antennas are oriented so that the first transmitting and first receiving antennas form a first symmetrical pair of antennas, and the second transmitting and second receiving antennas form a second symmetric pair of antennas, and the magnetic dipole moment of at least one of the antennas forms a substantially non-zero angle c logging tool. 8. The method according to claim 1, which further includes the step of determining the profile of resistivity across the boundary of the formation. 9. The method of claim 8, wherein the step of determining the relative dip includes determining a resistivity profile across the formation boundary. 10. The method according to claim 8, in which the profile of the resistivity is determined either from the known data of the guide well, or from measuring the resistivity in the bottom of the well. 11. The method according to claim 10, in which the measurements of resistivity in the bottom of the well are provided with a logging tool or other tool placed on a common tool rod with a logging tool. 12. The method of claim 8, wherein the step of determining the relative drop is performed using a pre-computed lookup table. 13. The method according to item 12, in which the step of determining the relative fall includes determining the real values of the resistivity of the two layers of the formation separated by the boundary of the formation; the use of one or more pre-calculated look-up tables for the selected pair of resistivities to determine the directional response of the boundary to a unit of incidence, corresponding to the actual values of resistivity; and determining the relative drop by dividing the generated directional measurement by the scaling factor, the scaling factor being determined from a specific resistivity profile by calculating the directional response of the boundary per unit of incidence. 14. The method of claim 8, which further includes the steps of determining a scaling factor from a specific resistivity profile by calculating the directional response of the boundary per unit of incidence and determining the relative incidence by dividing the generated directional measurement by the scaling factor. 15. The method according to claim 8, in which the step of determining the relative fall includes inversion. 16. The method according to claim 1, in which the logging tool is a device placed on a non-rotating or slowly rotating wireline or drill string. 17. The method according to clause 16, in which the transmitting system includes two transmitting antennas, each transmitting antenna has a magnetic dipole moment aligned with the axis of the instrument; the receiving system includes two transverse receiving antennas with their magnetic dipole moments oriented in different directions but perpendicular to the axis of the logging tool, and two receiving antennas are located between two transmitting antennas at the first depth of the well, essentially in the middle between two transmitting antennas. 18. The method of claim 17, wherein the transmitting step includes supplying power to one of two transmitting antennas for transmitting electromagnetic energy to the formation; the measurement step includes measuring the first voltage signals associated with electromagnetic energy transmitted by one transmitting antenna using two receiving antennas, measuring the azimuth of the logging tool; determination of the relative azimuth of the border; generating the first directional measured voltage signal of the virtual transverse receiver in the relative azimuth of the boundary using a rotation matrix corresponding to the determined relative relative azimuth of the boundary with respect to the tool azimuth; and further comprising the steps of moving the logging tool inside the well to move the other of the two transmitting antennas to the first depth of the well; supplying power to the other of the two transmitting antennas for transmitting electromagnetic energy to the formation; measuring second voltage signals associated with electromagnetic energy transmitted by another transmitting antenna using two receiving antennas; measuring azimuth of a logging tool; determining the relative azimuth of the border; and generating a second directional measured voltage signal of the virtual transverse receiver along the relative azimuth of the boundary using a rotation matrix corresponding to a certain relative azimuth of the boundary relative to the azimuth of the tool; and combining the generated first and second voltage signals of the virtual transverse receiver to form a symmetrized directional measurement. 19. The method according to clause 16, in which the transmitting system includes a triaxial transmitting antenna; The receiving system includes triaxial receiving antennas. 20. The method according to claim 19, in which the vectors of the magnetic dipole moments of the three transmitting antennas are linearly independent and the vectors of the effective area of the antennas of the three receivers are linearly independent. 21. The method according to claim 19, in which the vectors of the magnetic dipole moments of the three transmitting antennas are mutually orthogonal and the vectors of the magnetic dipole moments of the three receiving antennas are mutually orthogonal. 22. The method of claim 19, wherein the three transmit antennas and three receive antennas are substantially co-located. 23. The method according to claim 19, in which the transmission step includes supplying power to one of the three transmitting antennas for transmitting electromagnetic energy to the formation; supplying power to a second of three transmitting antennas for transmitting electromagnetic energy to the formation; power supply to the third of the three transmitting antennas for transmitting electromagnetic energy to the formation; the measurement step includes measuring first voltage signals associated with electromagnetic energy by one transmitting antenna using three receiving antennas; measuring second voltage signals associated with electromagnetic energy by a second transmitting antenna using three receiving antennas; measuring third voltage signals associated with electromagnetic energy by a third transmitting antenna using three receiving antennas; and further comprising the steps of linearly combining the voltage signals measured by the respective three receivers to generate voltages, representing a pair of virtual transmitters and receivers from the transmitted transmitted transmitted freestyle orientations; the formation of associated voltages between three mutually orthogonal virtual transducers and receivers; and forming a symmetrized directional measurement using coupled voltages for pairs of symmetrical transmitter and successor. 24. The method according to claim 20, in which the pairs of signals of the virtual receiver-transmitter with a fixed orientation are generated from the measured first, second and third voltage signals using a 3-dimensional rotation matrix corresponding to a fixed orientation. 25. The method according to item 23, in which the relative azimuth of the boundary is determined according to Ιαη ^-ι (ΥΖ / ΧΖ) or 1ap ^{- |} (2 * ХУ / (ХХ-УУ)). where ΥΖ is the voltage for the dipole magnetic moment of the receiving antenna oriented along Y, and the transmitting antenna oriented along Ζ, ΧΖ is the voltage for the dipole magnetic moment of the receiving antenna oriented in X, and the transmitting antenna oriented in Ζ, XY is the voltage for the dipole magnetic moment of the receiving antenna oriented along X, and the transmitting antenna oriented along Y, XX is the voltage for the dipole magnetic moment of the receiving antenna oriented along X, and the transmitting antenna oriented along X, The UE is the voltage for the dipole magnetic moment of the receiving antenna oriented along Υ, and the transmitting antenna oriented along Υ, Ζ is the direction along the axis of the tool, Χ is the direction along the reference azimuthal angle and perpendicular to Ζ, Υ is perpendicular to Χ and Ζ; and Χ-Υ-Ζ form a Cartesian coordinate system. 26. The method according to item 23, in which directional measurements are formed using Χ'Ζ-ΖΧ 'associated voltage, where Χ' is the direction in the relative azimuth of the boundary and is perpendicular to the axis Ζ of the tool. 27. The method according to claim 4, in which the transmitting system includes two separately located transmitting antennas, each transmitting antenna having a magnetic dipole moment inclined relative to the axis of the instrument by a first angle; the receiving system includes at least one receiving antenna located between two transmitting antennas at a first depth of the well, the receiving antenna having a magnetic dipole moment inclined relative to the axis of the instrument by a second angle. 28. The method of claim 27, wherein the transmitting step includes supplying power to one of the two transmitting antennas for transmitting electromagnetic energy to the formation; the measurement step includes measuring the first voltage signals associated with the electromagnetic energy transmitted by one transmitting antenna using a receiving antenna, determining the azimuthal orientation of the logging tool and rotating the drill string so as to rotate the transmitting and receiving antennas around the axis of the logging tool, and additionally including the steps of moving the logging tool in the well so as to allow the movement of the other of the two transmitting nn the first borehole depth; supplying power to the other of the two transmitting antennas with the possibility of transmitting electromagnetic energy to the formation; measuring second voltage signals associated with electromagnetic energy transmitted by another transmitting antenna using a receiving antenna; determining the azimuthal orientation of the logging tool; and rotation of the drill string with the possibility of rotation of the transmitting and receiving antennas around the axis of the logging tool, and the relative azimuth of the boundary is determined from the measured first and second voltage signals; and the measured first and second voltage signals are combined to form a symmetrical directional measurement. 29. A method for describing a subsurface formation with a logging tool located in a well passing through the formation, the logging tool having a longitudinal axis and provided with at least a transmitting system and a receiving system that together comprise at least one set of upper antennas and one set lower antennas, this method includes the steps of placing a logging tool inside the well so that the transmitting system and the receiving system are located in the immediate vicinity of the survey the boundary of the formation; measuring the azimuthal orientation of the logging tool; transmitting electromagnetic energy to the formation using a transmission system; measuring signals associated with electromagnetic energy transmitted by a transmitting system using a receiving system; forming a symmetrized directional measurement using the measured signals; and images of a specific directional measurement as a function of depth for many different depths; and using discontinuity in the rate of change of the depicted directional measurement to identify the depth at which at least one of the upper and lower antennas crosses the boundary of the formation. 30. A logging device for describing a subsurface formation through which a well passes, including a body configured to move in the well, having a longitudinal axis; a transmitting system located in the housing for transmitting electromagnetic energy to the formation; a receiving system located in the housing for measuring signals associated with electromagnetic energy transmitted by the transmitting system; - 19 006075 means for determining the relative azimuth of the considered formation boundary in the immediate vicinity of the well; means for generating a symmetric directional measurement using signals measured by the receiving system and the relative azimuth of the boundary determined by the azimuth determination means; and means for determining the relative dip of the formation boundary using the generated directional measurement. 31. The logging device according to claim 30, wherein the body is arranged to be placed in the drill string and further adapted to rotate with the drill string. 32. The logging device according to claim 30, wherein the body is configured to be placed on the logging cable. ^T 1 2 = I T ₂ cx